QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended September 30, 2011

or

¨

TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from
to

Commission File Number: 1-16735

PENN VIRGINIA RESOURCE PARTNERS, L.P.

(Exact name of registrant as specified in its charter)

Delaware

23-3087517

(State or other jurisdiction of

incorporation or organization)

(I.R.S. Employer

Identification No.)

FIVE RADNOR CORPORATE CENTER, SUITE 500

100 MATSONFORD ROAD

RADNOR, PA 19087

(Address of principal executive offices) (Zip Code)

(610) 975-8200

(Registrants telephone number, including area code)

(Former name,
former address and former fiscal year, if changed since last report)

Indicate by
check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 (Exchange Act) during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. x Yes ¨ No

Indicate by check mark whether the registrant has submitted
electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was
required to submit and post such files). Yes x No ¨

Indicate by a check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller
reporting company. See the definitions of large accelerated filer, accelerated filer and smaller reporting company in Rule 12b-2 of the Exchange Act.

Large accelerated filer

¨

Accelerated filer

x

Non-accelerated filer

¨ (Do not check if a smaller reporting company)

Smaller reporting company

¨

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the
Exchange Act). ¨ Yes x No

As of October 17, 2011, 70,981,867 common units representing limited partner interests were outstanding.

CONSOLIDATED STATEMENT OF PARTNERS CAPITAL AND COMPREHENSIVE INCOME  unaudited

(in thousands)

Common Units (1)

Accumulated OtherComprehensiveIncome

Noncontrollinginterests of PVR (2)

Total

ComprehensiveIncome

Balance at December 31, 2010

38,293

$

213,646

$

159

$

220,845

$

434,650

Unit-based compensation

24

6,756

6,756

Costs associated with merger

(11,240

)

(11,240

)

Units issued to acquire non-controlling interests

32,665

204,537

250

(204,787

)



Distributions paid

(84,302

)

(15,394

)

(99,696

)

Net income (loss)

79,690

(664

)

79,026

$

79,026

Other comprehensive income

366

366

366

Balance at September 30, 2011

70,982

$

409,087

$

775

$



$

409,862

$

79,392

Common Units (1)

Accumulated OtherComprehensiveIncome (Loss)

Noncontrollinginterests of PVR

Total

ComprehensiveIncome

Balance at December 31, 2009

38,293

$

250,240

$

(544

)

$

235,907

$

485,603

Unit-based compensation



6,024

6,024

Loss on issuance of subsidiary units

(1,508

)

1,508



Purchase of subsidiary units

(11,665

)

10,573

(1,092

)

Distributions paid

(45,326

)

(46,077

)

(91,403

)

Net income

27,262

18,671

45,933

$

45,933

Other comprehensive income

585

919

1,504

1,504

Balance at September 30, 2010

38,293

$

219,003

$

41

$

227,525

$

446,569

$

47,437

(1)

The outstanding common units have been adjusted to reflect the effect of the Merger; see Note 1, Organization, and Note 2, Basis of Presentation. PVG unitholders
received consideration of 0.98 of a PVR common unit for each PVG common unit.

(2)

Effective with the Merger, see Note 1, Organization, and Note 2, Basis of Presentation, noncontrolling interests no longer exist and have become part of common units.

The accompanying notes are an integral part of these Consolidated Financial Statements.

Penn Virginia Resource Partners, L.P. is a publicly traded Delaware master limited partnership, the limited partner
units representing limited partner interests which are listed on the New York Stock Exchange (NYSE) under ticker symbol PVR. As used in these Notes to Consolidated Financial Statements, the Partnership,
PVR, we, us or our mean Penn Virginia Resource Partners, L.P. and, where the context requires, includes our subsidiaries.

We are principally engaged in the management of coal and natural resource properties and the gathering and processing of natural gas in the United States. We currently conduct operations in two business
segments: (i) coal and natural resource management and (ii) natural gas midstream.

Our coal and natural resource
management segment primarily involves the management and leasing of coal properties and the subsequent collection of royalties. Our coal reserves are located in Illinois, Indiana, Kentucky, New Mexico, Tennessee, Virginia and West Virginia. We also
earn revenues from other land management activities, such as selling standing timber, leasing fee-based coal-related infrastructure facilities to certain lessees and end-user industrial plants, collecting oil and gas royalties and from coal
transportation, or wheelage, fees.

Our natural gas midstream segment is engaged in providing natural gas processing,
gathering and other related services. We own and operate natural gas midstream assets located in Oklahoma, Texas and Pennsylvania. Our natural gas midstream business derives revenues primarily from gas processing contracts with natural gas producers
and from fees charged for gathering natural gas volumes and providing other related services. In addition, we are a partner in several joint ventures that gather and transport natural gas and water. We own a natural gas marketing business, which
aggregates third-party volumes and sells those volumes into intrastate pipeline systems and at market hubs accessed by various interstate pipelines.

On September 21, 2010, we entered into an Agreement and Plan of Merger (the Merger Agreement) by and among PVR, Penn Virginia Resource GP, LLC (PVR GP), Penn Virginia GP
Holdings, L.P. (PVG), PVG GP LLC (PVG GP) and PVR Radnor, LLC (Merger Sub), a wholly owned subsidiary of PVR. The Merger Agreement received final approval by PVR unitholders on February 16, 2011 and PVG
unitholders on March 9, 2011. Pursuant to the Merger Agreement, PVG and PVG GP were merged into Merger Sub, with Merger Sub as the surviving entity (the Merger). Merger Sub was subsequently merged into PVR GP, with PVR GP being the
surviving entity as a subsidiary of PVR. In the transaction, PVG unitholders received consideration of 0.98 PVR common units for each PVG common unit, representing aggregate consideration of approximately 38.3 million PVR common units. Pursuant
to the Merger Agreement and the Fourth Amended and Restated Agreement of Limited Partnership of PVR, the incentive distribution rights held by PVRs general partner were extinguished, the 2.0% general partner interest in PVR held by PVRs
general partner was converted into a noneconomic management interest and approximately 19.6 million PVR common units owned by PVG were cancelled. The Merger closed on March 10, 2011. After the effective date of the Merger and related
transactions, the separate existence of each of PVG, PVG GP and Merger Sub ceased, and PVR GP survives as a wholly-owned subsidiary of PVR.

Historically, PVGs ownership of PVRs general partner gave it control of PVR. During the periods that PVG controlled PVR (prior to March 10, 2011), PVG had no substantial assets or
liabilities other than those of PVR. PVGs consolidated financial statements included noncontrolling owners interest of consolidated subsidiaries, which reflected the proportion of PVR common units owned by PVRs unitholders other
than PVG. These amounts are reflected in the historical financial balances presented up to consummation of the Merger.

PVG is
considered the surviving consolidated entity for accounting purposes, while PVR is the surviving consolidated entity for legal and reporting purposes. The Merger was accounted for as an equity transaction. Therefore, the changes in ownership
interests as a result of the Merger did not result in gain or loss recognition.

After the Merger, the board of directors of
PVRs general partner, PVR GP, consisted of nine members, six of whom were existing members of the PVR GP board of directors before the Merger and three of whom were the three existing members of the conflicts committee of the board of
directors of PVG GP prior to the Merger. On June 22, 2011, PVR held its annual unitholder meeting and all nine directors were re-elected to serve on the PVR GP board until PVRs 2012 annual unit holder meeting.

During the nine months ended September 30, 2011 and for the year ended
December 31, 2010, we incurred $6.6 million and $4.6 million of direct costs associated with the Merger. The aggregate costs of $11.2 million were charged to partners capital upon the effective date of the Merger in 2011. At
December 31, 2010, the $4.6 million of costs incurred at that time were included in other long-term assets on the consolidated balance sheet, and were transferred to partners capital upon the effective date of the merger. Cumulative costs
incurred and paid during the three and nine months ended September 30, 2011 are reported under the caption Cash paid for merger in the financing activities section of the consolidated statement of cash flows.

The following diagrams depict the ownership structure of PVR and PVG before and immediately following the Merger:

These financial statements were originally the financial statements of PVG prior to the effective date of the Merger.
The Merger was accounted for in accordance with consolidation accounting standards for changes in a parents ownership interest in a subsidiary. Under these accounting standards, the exchange of PVG common units for PVR common units was
accounted for as a PVG equity issuance and PVG was the surviving entity for accounting purposes. Although PVG was the surviving entity for accounting purposes, PVR is the surviving entity for legal and reporting purposes; consequently, the name on
these financial statements was changed from Penn Virginia GP Holdings, L.P. to Penn Virginia Resource Partners, L.P.

The reconciliation of PVRs net income, as historically reported, to the net income reported in these financial statements is as follows (in thousands):

Pursuant to the Merger, PVGs unitholders received 0.98 of a PVR common unit for each PVG common unit they owned, or approximately
38.3 million of PVR common units in the aggregate, in exchange for all outstanding PVG common units. Also pursuant to the Merger, approximately 19.6 million PVR common units that were held by PVG were cancelled. As a result, PVRs
common units outstanding increased from 52.3 million to 71.0 million. However, for historical reporting purposes, the impact of this change was accounted for as a reverse unit split of 0.98 to 1.0. Therefore, since PVG was the surviving entity
for accounting purposes, the weighted average common units outstanding used for basic and diluted earnings per unit calculations are PVGs historical weighted average common units outstanding adjusted for the retrospective application of the
reverse unit split. Amounts reflecting historical PVG common unit and per common unit amounts included in this report have been restated for the reverse unit split.

Our Consolidated Financial Statements include the accounts of PVR and all of our wholly owned subsidiaries. Investments in non-controlled entities over which we exercise significant influence are
accounted for using the equity method. Intercompany balances and transactions have been eliminated in consolidation. Our Consolidated Financial Statements have been prepared in accordance with accounting principles generally accepted in the United
States of America.

These statements involve the use of estimates and judgments where appropriate. In the opinion of management, all adjustments, consisting of normal recurring accruals, considered necessary for a
fair presentation of our Consolidated Financial Statements have been included. Our Consolidated Financial Statements should be read in conjunction with our consolidated financial statements and footnotes included in PVRs and PVGs Annual
Reports on Form 10-K for the year ended December 31, 2010. Operating results for the three and nine months ended September 30, 2011 are not necessarily indicative of the results that may be expected for the year ending December 31,
2011.

Management has evaluated all activities of PVR through the date upon which our Consolidated Financial Statements were
issued and concluded that no subsequent events have occurred that would require recognition in the Consolidated Financial Statements, but disclosure is required in the Notes to Consolidated Financial Statements. See Note 13 to the Consolidated
Financial Statements.

In June 2011, the Financial Accounting Standards Board (FASB) issued an Accounting
Standards Update (ASU) aimed at increasing the prominence of other comprehensive income in the financial statements by requiring comprehensive income to be reported in either a single statement or in two consecutive statements reporting
net income and other comprehensive income. This amendment does not change items that are reported in other comprehensive income or requirements to report reclassification of items from other comprehensive income to net income. This ASU eliminates
the option to report other comprehensive income and its components in the statement of changes in partners capital. We will be required to adopt the guidance for fiscal years, and interim periods within those years, beginning after
December 15, 2011. Management is considering which presentation would be more beneficial to the readers of our financials and will adopt this ASU for interim periods beginning in 2012.

All dollar and unit amounts presented in the tables to these Notes are in thousands unless otherwise indicated.

3.

Acquisitions

In the following paragraphs, all references to coal, oil and gas interests acquired are unaudited. The factors we used
to determine the fair market value of the acquisition include, but are not limited to, discounted future net cash flows on a risk-adjusted basis, geographic location, quality of resources, potential marketability and financial condition of lessees.

Business Combination

Middle Fork

On
January 25, 2011, we completed an acquisition to acquire certain mineral rights and associated oil and gas royalty interests in Kentucky and Tennessee for approximately $95.7 million. The results of Middle Fork operations have been included in
the consolidated financial statements since that date. The mineral rights include approximately 102 million tons of coal reserves and resources. The coal is primarily steam coal and expands our geographic scope in the Central Appalachia coal
region.

We acquired assets of $97.8 million and liabilities of $2.1 million, which primarily represent deferred income.
Deferred income represents minimum royalty payments paid by operators of the properties that may be recouped through future production. Funding for the acquisition was provided by borrowings under our revolving credit facility (the
Revolver).

The Middle Fork acquisition has been accounted for using the purchase method of accounting. Under the
purchase method of accounting, the total purchase price has been allocated to the tangible assets acquired and liabilities assumed. Below is the detailed allocation based upon acquisition date fair values:

Fair value of assets acquired and liabilities assumed:

Coal mineral interests

$

94,410

Oil and gas interests

2,857

Land

449

Support equipment

60

Deferred income

(2,018

)

Other liabilities

(42

)

Fair value of assets acquired and liabilities assumed

$

95,716

The following pro forma financial information reflects the consolidated results of our operations as if
the Middle Fork acquisition had occurred on January 1, 2010. The pro forma information includes adjustments for royalty revenues, operating expenses, general and administrative expenses, depreciation and depletion of the acquired property and
equipment, interest

expense for acquisition debt and the change in weighted average common units resulting from the Merger. The pro forma financial information is not necessarily indicative of the results of
operations as it would have been had these transactions been effected on the assumed date (in thousands, except per unit data):

Three Months EndedSeptember 30,

Nine Months EndedSeptember 30,

2011

2010

2011

2010

Revenues

$

308,352

$

226,046

$

873,054

$

627,054

Net income attributable to PVR

$

35,857

$

7,937

$

79,853

$

28,890

Net income per limited partner unit, basic and diluted

$

0.50

$

0.21

$

1.26

$

0.75

During the year, we have made other acquisitions that individually and in the aggregate are not material
for disclosure purposes. The aggregate cost of all other acquisitions was a net $26.9 million.

4.

Fair Value Measurements

We apply the authoritative accounting provisions for measuring fair value of both our financial and nonfinancial assets
and liabilities. Fair value is an exit price representing the expected amount we would receive to sell an asset or pay to transfer a liability in an orderly transaction with market participants at the measurement date. We have followed consistent
methods and assumptions to estimate the fair values as more fully described in our Annual Report on Form 10-K for the year ended December 31, 2010.

Our financial instruments that are subject to fair value disclosure consist of cash and cash equivalents, accounts receivable, accounts payable, derivatives and long-term debt. At September 30, 2011,
the carrying values of all of these financial instruments, except the long-term debt with fixed interest rates, approximated fair value. The fair value of floating-rate debt approximates the carrying amount because the interest rates paid are based
on short-term maturities. The fair value of our fixed-rate long-term debt is estimated based on the published market prices for the same or similar issues (a Level 1 category fair value measurement). As of September 30, 2011, the fair value of
our fixed-rate debt was $285.0 million.

Nonrecurring Fair Value Measurements

We completed the Middle Fork acquisition on January 25, 2011. See Note 3, Acquisitions, for a description of this
acquisition. In connection with our accounting for this acquisition, it was necessary for us to estimate the values of the assets acquired and liabilities assumed, which involved the use of various assumptions. The most significant assumptions, and
the ones requiring the most judgment, involved the estimated fair values of coal minerals and oil and gas royalties along with the related pricing and production activities. The coal minerals acquisition included nonfinancial assets and liabilities
that were measured at fair value as of the acquisition date. The total purchase price allocation was $95.7 million.

During
the year, we have made other acquisitions that individually and in the aggregate are not material for disclosure purposes. The aggregate cost of all other acquisitions was a net $26.9 million.

The following table summarizes the fair value estimates for nonfinancial assets and liabilities measured at fair value on a nonrecurring
basis by category as of the acquisition date:

Fair Value Measurements, Using

Description

Fair ValueMeasurements atAcquisition Date

Quoted Prices inActive Markets forIdentical Assets(Level 1)

Significant OtherObservable Inputs(Level 2)

SignificantUnobservableInputs (Level 3)

Middle Fork assets (1)

$

97,776

$



$



$

97,776

Middle Fork liabilities (1)

(2,060

)





(2,060

)

Other acquisitions, net (2)

26,919





26,919

Total

$

122,635

$



$



$

122,635

(1)

The Middle Fork assets and liabilities were acquired on January 25, 2011.

(2)

Other acquisitions were completed in the second and third quarters of 2011.

Certain assets and liabilities, including our derivatives, are measured at fair value on a recurring basis in our Consolidated Balance
Sheet. The following tables summarize the valuation of these assets and liabilities for the periods presented:

Fair Value Measurements at September 30, 2011, Using

Description

Fair ValueMeasurements atSeptember 30, 2011

Quoted Prices inActive Markets forIdentical Assets(Level 1)

Significant OtherObservable Inputs(Level 2)

SignificantUnobservableInputs (Level 3)

Interest rate swap liabilities  current

$

(3,048

)

$



$

(3,048

)

$



Interest rate swap liabilities  noncurrent

(376

)



(376

)



Commodity derivative assets  current

1,381



1,381



Commodity derivative assets  noncurrent

332



332



Commodity derivative liabilities  current

(8,479

)



(8,479

)



Commodity derivative liabilities  noncurrent

(879

)



(879

)



Total

$

(11,069

)

$



$

(11,069

)

$



Fair Value Measurements at December 31, 2010, Using

Description

Fair ValueMeasurements atDecember 31, 2010

Quoted Prices inActive Markets forIdentical Assets(Level 1)

Significant OtherObservable Inputs(Level 2)

SignificantUnobservableInputs (Level 3)

Interest rate swap liabilities  current

$

(7,647

)

$



$

(7,647

)

$



Interest rate swap liabilities  noncurrent

(1,037

)



(1,037

)



Commodity derivative liabilities  current

(11,869

)



(11,869

)



Commodity derivative liabilities  noncurrent

(4,070

)



(4,070

)



Total

$

(24,623

)

$



$

(24,623

)

$



We used the following methods and assumptions to estimate the fair values:



Commodity derivatives: We utilize costless collars and swap derivative contracts to hedge against the variability in the fractionation, or
frac, spread. We determine the fair values of our commodity derivative agreements based on discounted cash flows based on quoted forward prices for the respective commodities. Each of these is a Level 2 input. We use the income approach, using
valuation techniques that convert future cash flows to a single discounted value.



Interest rate swaps: We have entered into the interest rate swaps (Interest Rate Swaps) to establish fixed rates on a portion
of the outstanding borrowings under the Revolver. We use an income approach using valuation techniques that connect future cash flows to a single discounted value. We estimate the fair value of the swaps based on published interest rate yield curves
as of the date of the estimate. Each of these is a Level 2 input.

We determine the fair values of our derivative agreements using third-party quoted forward prices for the respective commodities as of the
end of the reporting period and discount rates adjusted for the credit risk of our counterparties if the derivative is in an asset position and our own credit risk if the derivative is in a liability position. The following table sets forth our
commodity derivative positions as of September 30, 2011:

AverageVolumePer
Day

Swap Price

Weighted Average Price

Fair Value atSeptember 30, 2011

Put

Call

NGL  natural gasoline collar

(gallons

)

(per gallon)

Fourth quarter 2011

95,000

$

1.57

$

1.94

$

(2,492

)

NGL  natural gasoline collar

(gallons

)

(per gallon)

First quarter 2012 through fourth quarter 2012

54,000

$

1.75

$

2.02

(3,138

)

Crude oil collar

(barrels

)

(per barrel)

Fourth quarter 2011

400

$

75.00

$

98.50

109

Crude oil swap

(barrels

)

(per barrel

)

First quarter 2012 through fourth quarter 2012

600

$

88.62

1,604

Natural gas purchase swap

(MMBtu

)

(MMBtu

)

Fourth quarter 2011

6,500

$

5.80

(1,193

)

Natural gas purchase swap

(MMBtu

)

(MMBtu

)

First quarter 2012 through fourth quarter 2012

4,000

$

5.195

(1,370

)

Settlements to be paid in subsequent period

(1,165

)

Interest Rate Swaps

We have entered into the Interest Rate Swaps to establish fixed interest rates on a portion of the outstanding borrowings under the Revolver. The following table sets forth the positions of the Interest
Rate Swaps as of September 30, 2011:

Notional Amounts(in
millions)

Swap Interest Rates (1)

Fair Value
atSeptember 30, 2011

Term

Pay

Receive

October 2011  December 2011

$

250.0

3.37

%

LIBOR

$

(1,907

)

January 2011  December 2012

$

100.0

2.09

%

LIBOR

$

(1,517

)

(1)

References to LIBOR represent the 3-month rate.

For the Interest Rate Swaps, we reported a (i) net derivative liability of $3.4 million at September 30, 2011 and (ii) gain in accumulated other comprehensive income (AOCI) of
$0.8 million as of September 30, 2011. In connection with periodic settlements, we reclassified a total of $0.4 million of net hedging losses on the Interest Rate Swaps from AOCI to the derivatives line on the Consolidated Statements of Income
during the nine months ended September 30, 2011. See the following Financial Statement Impact of Derivatives section for the impact of the Interest Rate Swaps on our Consolidated Financial Statements.

The following table summarizes the effects of our derivative activities, as well as the location of gains (losses) on our Consolidated
Statements of Income for the periods presented:

Location
ofderivatives recognizedin income statement

Three Months EndedSeptember 30,

Nine Months EndedSeptember 30,

2011

2010

2011

2010

Derivatives not designated as hedging instruments:

Interest rate contracts (1)

Interest expense

$



$



$



$

(1,090

)

Interest rate contracts

Derivatives

(58

)

(2,568

)

(956

)

(7,739

)

Commodity contracts

Derivatives

8,748

(8,452

)

(5,333

)

(3,775

)

Total increase (decrease) in net income resulting from derivatives

$

8,690

$

(11,020

)

$

(6,289

)

$

(12,604

)

Realized and unrealized derivative impact:

Cash paid for commodity and interest rate contract settlements

Derivatives

$

(6,699

)

$

(2,435

)

$

(19,477

)

$

(6,493

)

Unrealized derivative gains (losses) (2)

15,389

(8,585

)

13,188

(6,111

)

Total increase (decrease) in net income resulting from derivatives

$

8,690

$

(11,020

)

$

(6,289

)

$

(12,604

)

(1)

This activity represents Interest Rate Swap amounts reclassified out of AOCI and into interest expense.

(2)

This activity represents unrealized gains (losses) in the interest expense and derivatives caption on our Consolidated Statements of Income.

The following table summarizes the fair value of our derivative instruments, as well as the locations of these instruments, on our
Consolidated Balance Sheets for the periods presented:

Balance Sheet Location

Fair Values as ofSeptember 30, 2011

Fair Values as ofDecember 31, 2010

DerivativeAssets

DerivativeLiabilities

DerivativeAssets

DerivativeLiabilities

Derivatives not designated as hedging instruments:

Interest rate contracts

Derivativeassets/liabilities current

$



$

3,048

$



$

7,647

Interest rate contracts

Derivative

assets/liabilities noncurrent



376



1,037

Commodity contracts

Derivative

assets/liabilities current

1,381

8,479



11,869

Commodity contracts

Derivative

assets/liabilities noncurrent

332

879



4,070

Total derivatives not designated as hedging instruments

$

1,713

$

12,782

$



$

24,623

Total fair value of derivative instruments

$

1,713

$

12,782

$



$

24,623

As of September 30, 2011, we were not party to derivative instruments that were classified as fair
value hedges or trading securities. In addition, as of September 30, 2011, we were not party to derivative instruments containing credit risk contingencies.

6.

Equity Investments

In September 2011, we entered into a joint venture to construct and operate a pipeline system to supply fresh water to
natural gas producers drilling in the Marcellus Shale in Pennsylvania. The 12-inch diameter steel pipeline will largely parallel the trunk line of our existing gathering system in Lycoming County. As of September 30, 2011 our non-cash
contribution to the joint venture was $4.8 million.

In accordance with the equity method of accounting, we recognized
earnings from all equity investments in the aggregate of $4.3 million and $6.5 million for the nine months ended September 30, 2011 and 2010, with a corresponding increase in the investment. The equity investments generally pay quarterly
distributions on their cash flow. We received distributions of $8.9 million and $9.0 million for the nine months ended September 30, 2011 and 2010. Equity earnings related to equity investments are recorded in other revenues on the Consolidated
Statements of Income. The equity investments for all joint ventures are included in the equity investments caption on the Consolidated Balance Sheets.

Summarized financial information of unconsolidated equity investments is as follows for the
periods presented:

September 30,2011

December 31,2010

Current assets

$

33,618

$

43,367

Noncurrent assets

$

213,591

$

203,595

Current liabilities

$

13,515

$

6,890

Noncurrent liabilities

$

2,520

$

5,147

Nine Months Ended September 30,

2011

2010

Revenues

$

43,074

$

52,722

Expenses

$

26,091

$

25,438

Net income

$

16,983

$

27,284

7.

Long-term Debt

Revolver

On April 19, 2011, our wholly-owned subsidiary, PVR Finco LLC, entered into the first amendment to the amended and restated secured credit agreement increasing our borrowing capacity under the
Revolver from $850.0 million to $1.0 billion and extending the maturity date to April 19, 2016. PVR Finco LLC has an option to increase the commitments under the Revolver by up to an additional $200.0 million, to a total of $1.2 billion, upon
receipt of commitments from one or more lenders. The amendment did not change the collateral provisions of the Revolver which is secured by substantially all of our assets, including recent acquisitions. The interest rate under the Revolver
fluctuates based on the ratio of our total indebtedness-to-EBITDA. Interest is payable at the base rate plus an applicable margin ranging from 0.75% to 1.75% if we select the base rate indebtedness option under the Revolver or at a rate derived from
LIBOR plus an applicable margin ranging from 1.75% to 2.75% if we select the LIBOR-based indebtedness option. As of September 30, 2011, net of outstanding indebtedness of $635.0 million and letters of credit of $1.6 million, we had remaining
borrowing capacity of $363.4 million on the Revolver. The weighted average interest rate on borrowings outstanding under the Revolver during the nine months ended September 30, 2011 was approximately 2.7%. We do not have a public rating for the
Revolver. As of September 30, 2011, we were in compliance with all covenants under the Revolver.

8.

Partners Capital and Distributions

As of September 30, 2011, partners capital consisted of approximately 71.0 million common units. As
noted in the Consolidated Statement of Partners Capital and Comprehensive Income and described in Note 1, Organization, and Note 2, Basis of Presentation, our outstanding number of units has changed significantly in connection with the Merger.

Net Income per Limited Partner Unit

Basic net income per limited partner unit is computed by dividing net income allocable to limited partners by the weighted average number of limited partner and vested deferred common units outstanding
during the period. Diluted net income per limited partner unit is computed by dividing net income allocable to limited partners by the weighted average number of limited partner and vested deferred common units outstanding during the period and,
when dilutive, phantom units. For the three and nine months ended September 30, 2011, weighted average awards of 39 thousand and 24 thousand phantom units were excluded from the diluted net income per limited partner unit calculation
because the inclusion of these phantom units would have had an antidilutive effect. The three and nine months ended September 30, 2010 computation of net income per limited partner unit relates to the financial statements of PVG prior to the
effective date of the Merger. For the three and nine months ended September 30, 2010, PVG did not have any phantom units or other participating securities outstanding, which would affect the computation of net income per limited partner unit.

We distribute 100% of Available Cash (as defined in our partnership agreement) within 45 days after the end of each quarter to unitholders of record and, prior to the Merger, to our general partner.
Available Cash is generally defined as all of our cash and cash equivalents on hand at the end of each quarter less reserves established by our general partner for future requirements. Our general partner has the discretion to establish cash
reserves that are necessary or appropriate to (i) provide for the proper conduct of our business, (ii) comply with applicable law, any of our debt instruments or any other agreements and (iii) provide funds for distributions to
unitholders and our general partner for any one or more of the next four quarters.

The following table reflects the
allocation of total cash distributions paid by us during the periods presented:

Three Months EndedSeptember 30,

Nine Months EndedSeptember 30,

2011

2010

2011

2010

PVG limited partners

$



$

15,239

$

15,239

$

45,326

PVR limited partners (1)

34,777

15,347

84,188

45,671

PVR phantom units

110

33

269

406

Total cash distribution paid during period

$

34,887

$

30,619

$

99,696

$

91,403

(1)

PVR limited partner unit distributions represent distributions paid to public unitholders and not to units owned by PVG prior to the Merger.

In June 2010, Penn Virginia Corporation (PVA) sold its remaining interest in PVG and as a result, PVA no
longer owned any limited or general partner interests in us or PVG. As a result of the divestiture, the related party transactions noted below are now considered arms-length and no longer require separate disclosures. Related party
transactions included charges from PVA for certain corporate administrative expenses which were allocable to us and our subsidiaries. Other transactions involved subsidiaries of PVA related to the marketing of natural gas, gathering and processing
of natural gas, and the purchase and sale of natural gas and NGLs in which we took title to the products. The Consolidated Statements of Income amounts noted below represent related party transactions prior to June 7, 2010 (date of
divestiture).

Three Months EndedSeptember 30,

Nine Months EndedSeptember 30,

2011

2010

2011

2010

Consolidated Statements of Income:

Natural gas midstream revenues

$



$



$



$

29,002

Other income

$



$



$



$

787

Cost of gas purchased

$



$



$



$

27,780

General and administrative

$



$



$



$

1,906

10.

Unit-Based Compensation

The Penn Virginia Resource GP, LLC Sixth Amended and Restated Long-Term Incentive Plan (the LTIP) permits
the grant of common units, deferred common units, unit options, restricted units and phantom units to employees and directors of our general partner and its affiliates. Common units and deferred common units granted under the LTIP are immediately
vested, and we recognize compensation expense related to those grants on the grant date. Restricted units and phantom units granted under the LTIP generally vest over a three-year period, and we recognize compensation expense related to those grants
on a straight-line basis over the vesting period. Compensation expense related to these grants is recorded in the general and administrative expenses caption on our Consolidated Statements of Income. During the nine months ended September 30,
2011, we granted 264 thousand phantom units at a weighted average grant-date fair value of $29.16, including 155 thousand time-based phantom units and 109 thousand performance-based phantom units.

Time-based phantom units vest over a three-year period, with one-third vesting in each year. Some of the phantom units vested during the
third quarter. A portion of the vested units were withheld for payroll taxes with the recipient receiving the net vested units.

Performance-based phantom units cliff-vest at the end of a three year period. The number of units that vest could range from 0% to 200%
and depends on the outcome of unit market performance compared to peers and key results of operations metrics. Performance-based phantom units are entitled to forfeitable distribution equivalent rights which accumulate over the term of the units and
will be paid in cash to the grantees at the date of vesting. The fair value of each performance-based phantom unit was estimated on the date of grant as $30.92 using a Monte Carlo simulation approach that uses the assumptions noted in the following
table. Expected volatilities are based on historical changes in the market value of our common units. We base the risk-free interest rate on the U.S. Treasury rate for the week of the grant having a term equal to the expected life of the phantom
units, continuously compounded.

2011

Expected volatility

54.53

%

Expected life

2.6 years

Risk-free interest rate

0.83

%

Prior to the Merger, the PVG GP, LLC Amended and Restated Long-Term Incentive Plan (the PVG
LTIP) likewise permitted the granting of PVG common units, deferred common units, unit options, restricted units and phantom units to employees and directors of the general partner and its affiliates. At the time of the Merger, deferred PVG
common units held on account of PVGs directors were automatically converted to deferred PVR common units at the rate of 0.98 deferred PVR common units for each deferred PVG common unit.

In connection with the normal three-year vesting of phantom and restricted units, as well as
common unit and deferred common unit awards, we recognized the following expense during the periods presented: .

Three Months EndedSeptember 30,

Nine Months EndedSeptember 30,

2011

2010

2011

2010

Restricted units

$



$



$



$

1,172

Phantom units

826

130

2,186

6,017

Director deferred and common units

140

285

619

862

$

966

$

415

$

2,805

$

8,051

11.

Commitments and Contingencies

Legal

We are involved, from time to time, in various legal proceedings arising in the ordinary course of business. While the ultimate results of these proceedings cannot be predicted with certainty, our
management believes that these claims will not have a material adverse effect on our financial position, results of operations or cash flows.

Environmental Compliance

As of September 30, 2011 and December 31, 2010, our environmental liabilities were $0.8 million and $0.9 million, which represents our best estimate of the liabilities as of those dates. We have
reclamation bonding requirements with respect to certain unleased and inactive properties. Given the uncertainty of when a reclamation area will meet regulatory standards, a change in this estimate could occur in the future.

Mine Health and Safety Laws

There are numerous mine health and safety laws and regulations applicable to the coal mining industry. However, since we do not operate any mines and do not employ any coal miners, we are not subject to
such laws and regulations. Accordingly, we have not accrued any related liabilities.

Customer Credit Risk

For the nine months ended September 30, 2011, revenues of each of our four largest natural gas midstream segment customers were
$124.4 million, $76.5 million, $75.3 million and $72.7 million, for an aggregate of 40% of our total consolidated revenues. At September 30, 2011, 35% of our consolidated accounts receivable related to these customers.

12.

Segment Information

Our reportable segments are as follows:



Coal and Natural Resource Management  Our coal and natural resource management segment primarily involves the management and leasing
of coal properties and the subsequent collection of royalties. We also earn revenues from other land management activities, such as selling standing timber, leasing coal-related infrastructure facilities and collecting oil and gas royalties.



Natural Gas Midstream  Our natural gas midstream segment is engaged in providing natural gas processing, gathering and other related
services. In addition, we own member interests in joint ventures that gather and transport natural gas and water.



The corporate and other caption primarily represents corporate functions.

In October 2011, the Coal and Natural Resources segment acquired properties which include coal, timber and oil and gas
assets for approximately $21.6 million in West Virginia. We used borrowings under our Revolver to finance this acquisition.

Certain statements contained herein include forward-looking statements. All statements that express beliefs, expectations,
estimates or intentions, as well as those that are not statements of historical fact, are forward-looking statements. Words such as may, will, could, should, expect, plan,
project, intend, anticipate, believe, estimate, predict, potential, pursue, target, continue, and similar expressions are
intended to identify such forward-looking statements. Because such statements include risks, uncertainties and contingencies, actual results may differ materially from those expressed or implied by such forward-looking statements. These risks,
uncertainties and contingencies include, but are not limited to, the following:



the volatility of commodity prices for natural gas, natural gas liquids, or NGLs, and coal;



our ability to access external sources of capital;



any impairment writedowns of our assets;



the relationship between natural gas, NGL and coal prices;



the projected demand for and supply of natural gas, NGLs and coal;



competition among producers in the coal industry generally and among natural gas midstream companies;



the extent to which the amount and quality of actual production of our coal differs from estimated recoverable coal reserves;



our ability to generate sufficient cash from our businesses to maintain and pay the quarterly distribution to our unitholders;



the experience and financial condition of our coal lessees and natural gas midstream customers, including our lessees ability to satisfy their
royalty, environmental, reclamation and other obligations to us and others;

environmental risks affecting the mining of coal reserves or the production, gathering and processing of natural gas;



the timing of receipt of necessary governmental permits by us or our lessees;



hedging results;



accidents;



changes in governmental regulation or enforcement practices, especially with respect to environmental, health and safety matters, including with
respect to emissions levels applicable to coal-burning power generators;



uncertainties relating to the outcome of current and future litigation regarding mine permitting;



risks and uncertainties relating to general domestic and international economic (including inflation, interest rates and financial and credit markets)
and political conditions (including the impact of potential terrorist attacks); and



other risks set forth in our Annual Report on Form 10-K for the year ended December 31, 2010.

Additional information concerning these and other factors can be found in our press releases and public periodic filings with the
Securities and Exchange Commission, including our Annual Report on Form 10-K for the year ended December 31, 2010. Many of the factors that will determine our future results are beyond the ability of management to control or predict. Readers
should not place undue reliance on forward-looking statements, which reflect managements views only as of the date hereof. We undertake no obligation to revise or update any forward-looking statements, or to make any other forward-looking
statements, whether as a result of new information, future events or otherwise.

Managements Discussion and Analysis of Financial Condition and Results of Operations

The following discussion and analysis of the financial condition and results of operations of Penn Virginia Resource Partners, L.P. and
its subsidiaries (the Partnership, PVR, we, us or our) should be read in conjunction with our Consolidated Financial Statements and Notes thereto in Item 1. All dollar amounts
presented in the tables that follow are in thousands unless otherwise indicated.

Overview of Business

We are a publicly traded Delaware limited partnership principally engaged in the management of coal and natural resource properties and
the gathering and processing of natural gas in the United States.

On September 21, 2010, we entered into an Agreement
and Plan of Merger (the Merger Agreement) by and among PVR, Penn Virginia Resource GP, LLC (PVR GP), Penn Virginia GP Holdings, L.P. (PVG), PVG GP LLC (PVG GP) and PVR Radnor, LLC (Merger
Sub), a wholly owned subsidiary of PVR. The Merger Agreement received final approval by PVR unitholders on February 16, 2011 and PVG unitholders on March 9, 2011. Pursuant to the Merger Agreement, PVG and PVG GP were merged into
Merger Sub, with Merger Sub as the surviving entity (the Merger). Merger Sub was subsequently merged into PVR GP, with PVR GP being the surviving entity as a subsidiary of PVR. In the transaction, PVG unitholders received consideration
of 0.98 PVR common units for each PVG common unit, representing aggregate consideration of approximately 38.3 million PVR common units. Pursuant to the Merger Agreement and the Fourth Amended and Restated Agreement of Limited Partnership of
PVR, the incentive distribution rights held by PVRs general partner were extinguished, the 2.0% general partner interest in PVR held by PVRs general partner was converted into a noneconomic management interest and approximately
19.6 million PVR common units owned by PVG were cancelled. The Merger closed on March 10, 2011. After the effective date of the Merger and related transactions, the separate existence of each of PVG, PVG GP and Merger Sub ceased, and PVR
GP survives as a wholly-owned subsidiary of PVR.

Historically, PVGs ownership of PVRs general partner gave it
control of PVR. During the periods that PVG controlled PVR (prior to March 10, 2011), PVG had no substantial assets or liabilities other than those of PVR. PVGs consolidated financial statements included noncontrolling owners
interest of consolidated subsidiaries, which reflected the proportion of PVR common units owned by PVRs unitholders other than PVG. These amounts are reflected in the historical financial balances presented up to consummation of the Merger.

PVG is considered the surviving consolidated entity for accounting purposes, while PVR is the surviving consolidated entity
for legal and reporting purposes. The Merger was accounted for as an equity transaction. Therefore, the changes in ownership interests as a result of the Merger did not result in gain or loss recognition.

After the Merger, the board of directors of PVRs general partner, PVR GP, consisted of nine members, six of whom were existing
members of the PVR GP board of directors before the Merger and three of whom were the three existing members of the conflicts committee of the board of directors of PVG GP prior to the Merger. On June 22, 2011, PVR held its annual meeting and
all nine directors were re-elected to serve on the PVR GP board until PVRs 2012 annual unitholder meeting.

During the
nine months ended September 30, 2011 and for the year ended December 31, 2010, we incurred $6.6 million and $4.6 million of direct costs associated with the Merger. The aggregate costs of $11.2 million were charged to partners
capital upon the effective date of the Merger in 2011. At December 31, 2010, the $4.6 million of costs incurred at that time were included in other long-term assets on the consolidated balance sheet, and were transferred to partners
capital upon the effective date of the merger. Cumulative costs incurred and paid during the three and nine months ended September 30, 2011 are reported under the caption Cash paid for merger in the financing activities section of
the consolidated statement of cash flows.

For the nine months ended September 30, 2011, the following general business developments and corporate actions had an impact, or will have an impact, on our results of operations. A discussion of
these key developments follows:

Coal and Natural Resource Management Segment

Middle Fork Acquisition

On January 25, 2011, we completed an acquisition to acquire certain mineral rights and associated oil and gas royalty interests in Kentucky and Tennessee for approximately $95.7 million. The mineral
rights include approximately 102 million tons of coal reserves and resources. The coal is primarily steam coal and expands our geographic scope in the Central Appalachia coal region.

Oatsville Reserves

In June 2011, we acquired 26.8 million tons of additional coal reserves in the Illinois Basin for $13.5 million. The Oatsville Reserve properties are deep minable Springfield V seam coal located on
approximately 5,875 acres in Gibson and Pike counties in Indiana.

Natural Gas Midstream Segment

Aqua Joint Venture

In September 2011, we entered into a joint venture to construct and operate a pipeline system to supply fresh water to natural gas producers drilling in the Marcellus Shale in Pennsylvania. The 12-inch
diameter steel pipeline will largely parallel the trunk line of our existing gathering system in Lycoming County. As of September 30, 2011 our contribution to the joint venture was $4.8 million.

Marcellus Shale Construction

During 2010, we began construction of gathering systems in Wyoming and Lycoming Counties in Pennsylvania. We have completed initial construction of 12-inch gas gathering pipelines in Wyoming County and
began gathering natural gas on the system in June 2010. In February 2011, we commenced operations on the first phase of the Lycoming County system. In April 2011, we also began construction on the second phase of the Lycoming County system, which is
expected to be operational in the first quarter of 2012. Construction and development to provide gathering, compression and related services in Lycoming and Wyoming Counties is ongoing. These Wyoming and Lycoming Counties gathering and
transportation infrastructures are expected to capture anticipated volumes in the Marcellus Shale area, where we have been spending, and expect to continue to spend, a significant portion of our growth capital over the next year, and for the
foreseeable future.

Panhandle

Due to the increased well development activities in the Panhandle region of the Midstream operations, our system volumes have increased significantly over past years volumes. The increase in the
volumes we have under contract in the Granite Wash has outpaced the capacity of our processing plants in the Panhandle. Further, third-party processing plants in the Panhandle region, that we have traditionally relied on to manage overruns in
volumes, are fully utilized and unable to handle our excess volumes. Accordingly, we have had to forego processing a significant amount of our volumes in the Panhandle which has adversely impacted our gross margins during the third quarter. Although
we have recently been able to utilize some off system processing capacity, we expect these constraints to continue through the fourth quarter and the beginning of the first quarter 2012. We have taken affirmative steps to alleviate this processing
capacity constraint, including the acquisition of the Antelope Hills processing facility in June 2011, the previously announced Phase One expansion of the Antelope Hills facility from 20 mmcf/day to 80 mmcf/day, and the most recently announced Phase
Two expansion of that facility to bring the processing capacity to 140 mmcf/day. Phase One is scheduled to be in service in the first quarter of 2012 and is expected to provide significant relief to our current processing capacity constraints. Phase
Two is expected to be operational in the third quarter of 2012, and it will enable us to meet our expected future processing requirements as volumes continue to grow. We are also improving the connectivity between our Antelope Hills, Beaver and
Sweetwater plants to enable us to better utilize our Panhandle processing capabilities and better serve the growing needs of the area producers, including those in the Granite Wash.

2011 Commodity Prices

Coal royalties, which accounted for 86% of the coal
and natural resource management segment revenues for the nine months ended September 30, 2011 and 2010, were higher as compared to 2010. The increase was attributed to increased production and higher realized coal royalty per ton primarily in
the Central Appalachian and San Juan regions. Average coal

prices received by lessees have increased in 2011 compared to the same period of 2010 due to strong market pricing for thermal and metallurgical coal.

The average commodity prices for crude oil and natural gas liquids, or NGLs, for 2011 increased from levels experienced in 2010, while
natural gas prices decreased for the comparable periods.

Revenues, profitability and the future rate of growth of our natural
gas midstream segment are highly dependent on market demand and prevailing NGL and natural gas prices. Historically, changes in the prices of most NGL products have generally correlated with changes in the price of crude oil. NGL and natural gas
prices have been subject to significant volatility in recent years in response to changes in the supply and demand for NGL products and natural gas market demand. As part of our risk management strategy, we use derivative financial instruments to
hedge NGLs sold and natural gas purchased. Our derivative financial instruments include costless collars and swaps. Based upon current volumes, we have entered into hedging arrangements covering 105% and 62% of our commodity-sensitive volumes in
2011 and 2012. The coverage amounts are high due to the processing capacity constraints in the Panhandle region. These constraints have caused PVR to bypass more of its owned natural gas without processing; lowering the net NGL recoveries specific
to PVR. Historically, we have targeted hedging 50% to 60% of our commodity sensitive volumes.

Liquidity and Capital Resources

Cash Flows

On an ongoing basis, we generally satisfy our working capital requirements and fund our capital expenditures using cash generated from our operations, borrowings under the Revolver and proceeds from debt
and equity offerings. As discussed in more detail in  Sources of Liquidity below, as of September 30, 2011, we had availability of $363.4 million on the Revolver. We fund our debt service obligations and distributions to
unitholders solely using cash generated from our operations. We believe that the cash generated from our operations and our borrowing capacity will be sufficient to meet our working capital requirements, anticipated capital expenditures (other than
major capital improvements or acquisitions), debt service and distributions. However, our ability to meet these requirements in the future will depend upon our future operating performance, which will be affected by prevailing economic conditions in
the coal industry and natural gas midstream market, most of which are beyond our control.

The following table summarizes our
statements of cash flow for the periods presented:

Nine Months Ended September 30,

2011

2010

Cash flows from operating activities:

Net income

$

79,026

$

45,933

Adjustments to reconcile net income to net cash provided by operating activities (summarized)

63,435

72,939

Net changes in operating assets and liabilities

(153

)

21,959

Net cash provided by operating activities

142,308

140,831

Net cash used in investing activities (summarized)

(261,373

)

(74,858

)

Net cash provided by (used in) financing activities (summarized)

117,009

(66,772

)

Net decrease in cash and cash equivalents

$

(2,056

)

$

(799

)

Cash Flows From Operating Activities

The overall increase in net cash provided by operating activities in the nine months ended September 30, 2011 as compared to the same period in 2010 was driven by an increase in coal royalties and an
increase in the natural gas midstream segments gross margin. These increases were partially offset by net change in operating assets and liabilities, increased operating expenses, interest expense and derivative settlements paid.

Net cash used in investing activities was primarily for capital expenditures. The following table sets forth our capital expenditures
program, adjusted for accruals and noncash items, for the periods presented:

Nine Months EndedSeptember 30,

2011

2010

Coal and natural resource management

Acquisitions

$

111,976

$

17,870

Maintenance

687

484

Total

112,663

18,354

Natural gas midstream

Acquisitions

12,243



Internal growth

127,498

53,011

Maintenance

7,845

9,873

Total

147,586

62,884

Total capital expenditures

$

260,249

$

81,238

In January 2011, we completed the acquisition of the Middle Fork properties, which added significant coal
reserves to our coal and natural resource segment in the Central Appalachia region. In June 2011, we completed two additional acquisitions. The Oatsville acquisition was in the Illinois Basin and we acquired 26.8 million tons of additional coal
reserves. The Antelope Hills plant acquisition added capacity to our Panhandle system in our Natural Gas Midstream segment. Our natural gas midstream internal growth capital expenditures for the nine months ended September 30, 2011 and 2010
were expended primarily to expand our operational footprint in our Marcellus Shale and Panhandle systems.

Cash Flows From Financing
Activities

During the nine months ended September 30, 2011, we incurred net borrowings of $227.0 million to fund our
coal and natural resources and natural gas midstream acquisitions and to finance the natural gas midstream capital expenditures. During the nine months ended September 30, 2010, we issued $300.0 million in senior notes and used the proceeds,
net of expenses, to pay down the Revolver. We also paid $6.6 million of direct costs incurred related to the Merger in 2011, and $3.7 million and $19.2 million of debt issuance costs for the nine months ended September 30, 2011 and 2010. During
the nine months ended September 30, 2011 and 2010 we paid cash distributions to our unitholders of $99.7 million and $91.4 million.

Certain Non-GAAP Financial Measures

We use non-GAAP (Generally Accepted Accounting Principles) measures to evaluate our business and performance. None of these measures should be considered an alternative to, or more meaningful than, net
income, operating income, cash flows from operating activities or any other measure of financial performance or liquidity presented in accordance with GAAP, or as indicators of our operating performance or liquidity.

Reconciliation of GAAP Net income to Non-GAAP Net income as adjusted

Net income

$

35,857

$

10,145

$

79,026

$

45,933

Adjustments for derivatives:

Derivative losses (gains) included in net income

(8,690

)

11,020

6,289

12,604

Cash payments to settle derivatives for the period

(6,699

)

(2,435

)

(19,477

)

(6,493

)

Net income, as adjusted (e)

$

20,468

$

18,730

$

65,838

$

52,044

(a)

EBITDA, or earnings before interest, tax and depreciation, depletion and amortization (DD&A), represents operating income plus DD&A, plus
impairments. We believe this presentation is commonly used by investors and professional research analysts in the valuation, comparison, rating and investment recommendations of companies in the coal and natural gas midstream industries. We use this
information for comparative purposes within the industry. EBITDA is not a measure of financial performance under GAAP and should not be considered as a measure of liquidity or as an alternative to net income.

(b)

Distributable cash flow represents net income plus DD&A expenses, plus impairments, plus (minus) derivative losses (gains) included in net income, plus (minus) cash
received (paid) to settle derivatives, minus equity earnings in joint ventures, plus cash distributions from joint ventures, minus maintenance capital expenditures, minus replacement capital expenditures. Distributable cash flow is a significant
liquidity metric which is an indicator of our ability to generate cash flows at a level that can sustain or support the quarterly cash distributions paid to our partners. Distributable cash flow is also the quantitative standard used by investors
and professional research analysts in the

valuation, comparison, rating and investment recommendations of publicly traded partnerships. Distributable cash flow is presented because we believe it is a useful adjunct to net cash provided
by operating activities under GAAP. Distributable cash flow is not a measure of financial performance under GAAP and should not be considered as an alternative to cash flows from operating, investing or financing activities, as an indicator of cash
flows, as a measure of liquidity or as an alternative to net income.

(c)

PVR limited partner unit distributions represent distributions paid to public unitholders and not units owned by PVG prior to the Merger.

(d)

Phantom unit grants were made under our long-term incentive plan. Service based phantom units receive nonforfeitable distribution rights; thus, we have presented
distributions paid to phantom unit holders in our total distributions paid to Partners.

(e)

Net income, as adjusted, represents net income adjusted to exclude the effects of non-cash changes in the fair value of derivatives and impairments. We believe this
presentation is commonly used by investors and professional research analysts in the valuation, comparison, rating and investment recommendations of companies in the natural gas midstream industry. We use this information for comparative purposes
within the industry. Net income, as adjusted, is not a measure of financial performance under GAAP and should not be considered as a measure of liquidity or as an alternative to net income.

Sources of Liquidity

Long-Term Debt

Revolver. On April 19, 2011, we entered into an amended and restated secured credit agreement increasing our borrowing
capacity under the Revolver from $850 million to $1.0 billion and extending the maturity date until April 19, 2016. The interest rate under the Revolver fluctuates based on the ratio of our total indebtedness-to-EBITDA. As of April 19,
2011, interest is payable at the base rate plus an applicable margin ranging from 0.75% to 1.75% if we select the base rate indebtedness option under the Revolver or at a rate derived from LIBOR plus an applicable margin ranging from 1.75% to 2.75%
if we select the LIBOR-based indebtedness option. As of September 30, 2011, net of outstanding indebtedness of $635.0 million and letters of credit of $1.6 million, we had remaining borrowing capacity of $363.4 million on the $1.0 billion
Revolver. The Revolver is available to provide funds for general partnership purposes, including working capital, capital expenditures, acquisitions and quarterly distributions. The weighted average interest rate on borrowings outstanding under the
Revolver during the nine months ended September 30, 2011 was approximately 2.7%. We do not have a public rating for the Revolver. As of September 30, 2011, we were in compliance with all of our covenants under the Revolver.

Interest Rate Swaps. We entered into interest rate swaps, or the Interest Rate Swaps, to establish fixed rates on a portion of the
outstanding borrowings under the Revolver. The following table sets forth the Interest Rate Swap positions as of September 30, 2011:

Notional Amounts(in millions)

Swap Interest Rates (1)

Term

Pay

Receive

October 2011  December 2011

$

250.0

3.37

%

LIBOR

December 2011  December 2012

$

100.0

2.09

%

LIBOR

(1)

References to LIBOR represent the 3-month rate.

After considering the applicable margin of 2.25% in effect as of September 30, 2011, the total interest rate on the $250.0 million portion of the Revolver borrowings covered by the Interest Rate
Swaps was 5.62% as of September 30, 2011.

Senior Notes. In April 2010, we sold $300.0 million of Senior Notes due
on April 15, 2018 with an annual interest rate of 8.25%, which is payable semi-annually in arrears on April 15 and October 15 of each year. The Senior Notes were sold at par, equating to an effective yield to maturity of 8.25%. The
net proceeds from the sale of the Senior Notes of $292.6 million, after deducting fees and expenses of $7.4 million, were used to repay borrowings under the Revolver. The Senior Notes are senior to any subordinated indebtedness, and are effectively
subordinated to all of our secured indebtedness including the Revolver to the extent of the collateral securing that indebtedness. The obligations under the Senior Notes are fully and unconditionally guaranteed by our current and future
subsidiaries, which are also guarantors under the Revolver.

Future Capital Needs and Commitments

As of September 30, 2011, our remaining borrowing capacity under the $1.0 billion Revolver of $363.4 million is sufficient to meet
our anticipated 2011 capital needs and commitments (other than major capital improvements or acquisitions). Our short-term cash requirements for operating expenses and quarterly distributions to our unitholders are expected to be funded through
operating cash flows. In 2011, we

expect to invest approximately $180 million to $200 million in internal growth capital, excluding acquisitions. The majority of the 2011 internal growth capital is expected to be incurred in the
natural gas midstream segment, primarily in the Marcellus Shale region. Long-term cash requirements for acquisitions and internal growth capital are expected to be funded by operating cash flows, borrowings under the Revolver and issuances of
additional debt and equity securities, if available under commercially acceptable terms.

Part of our long-term strategy is to
increase cash available for distribution to our unitholders by making acquisitions and other capital expenditures. Our ability to make these acquisitions and other capital expenditures in the future will depend largely on the availability of debt
financing and on our ability to periodically use equity financing through the issuance of new common units. Future financing will depend on various factors, including prevailing market conditions, interest rates and our financial condition and
credit rating.

Results of Operations

Consolidated Review

The following table presents summary
consolidated results for the periods presented:

Three Months Ended September 30, 2011 Compared with Three Months Ended September 30, 2010

The following table sets forth a summary of certain financial and other data for our coal and natural resource management segment and the
percentage change for the periods presented:

Three Months EndedSeptember 30,

Favorable(Unfavorable)

%
ChangeFavorable(Unfavorable)

2011

2010

Financial Highlights

Revenues

Coal royalties

$

40,977

$

34,983

$

5,994

17

%

Coal services

2,151

1,975

176

9

%

Timber

1,457

1,437

20

1

%

Oil and gas royalty

1,234

631

603

96

%

Other

1,637

1,382

255

18

%

Total revenues

47,456

40,408

7,048

17

%

Expenses

Operating

4,282

2,908

(1,374

)

(47

%)

General and administrative

3,771

3,686

(85

)

(2

%)

Depreciation, depletion and amortization

9,572

7,440

(2,132

)

(29

%)

Total expenses

17,625

14,034

(3,591

)

(26

%)

Operating income

$

29,831

$

26,374

$

3,457

13

%

Other data

Coal royalty tons by region

Central Appalachia

4,753

4,805

(52

)

(1

%)

Northern Appalachia

598

828

(230

)

(28

%)

Illinois Basin

1,191

987

204

21

%

San Juan Basin

2,937

1,910

1,027

54

%

Total tons

9,479

8,530

949

11

%

Coal royalties revenues by region

Central Appalachia

$

29,219

$

25,868

$

3,351

13

%

Northern Appalachia

1,821

2,177

(356

)

(16

%)

Illinois Basin

3,327

2,756

571

21

%

San Juan Basin

6,610

4,182

2,428

58

%

Total royalties

$

40,977

$

34,983

$

5,994

17

%

Coal royalties per ton by region ($/ton)

Central Appalachia

$

6.15

$

5.38

$

0.77

14

%

Northern Appalachia

3.05

2.63

0.42

16

%

Illinois Basin

2.79

2.79



0

%

San Juan Basin

2.25

2.19

0.06

3

%

Average royalties per ton

$

4.32

$

4.10

$

0.22

5

%

Revenues

Coal royalties revenues increased due to higher production and realized coal royalties per ton. The Middle Fork acquisition on January 25, 2011 contributed $3.2 million to the Central Appalachia coal
royalties and 0.5 million tons of coal production. Offsetting the newly acquired production in the Central Appalachia region was a decrease in production related to the temporary movement of longwall operations off of PVRs property.
Equipment added during 2010 to the mines in the San Juan Basin continues to increase production and related coal royalties compared to the prior year.

Coal royalties per ton increased in all regions, except for the Illinois Basin, which did
not change, for the third quarter of 2011 compared to the same quarter of last year. In Central Appalachia, average coal prices received by lessees have increased due to the strong market pricing for thermal and metallurgical coal.

Consistent with the increase in coal production, the coal services revenues have increased in 2011.

Oil and gas royalty income has increased in the third quarter of 2011 over the same period of 2010 due to the 2011 settlement against a
producer for deductions made on past royalties, as well as the $0.2 million royalties earned from the Middle Fork acquisition.

Other revenues in the third quarter of 2011 have increased due to minimum royalty forfeitures. Based upon lease contracts, which vary by
lessee, lessees paying minimum royalties have an established time to recoup minimum royalties paid. If the stated levels of production have not occurred after the exhaustion of that time period, the minimum payments are recognized into earnings.

Expenses

Operating expenses have increased primarily due to coal royalty costs and the recent Middle Fork acquisition. Increased mining activity by
our lessees from subleased properties in the Central Appalachia region increased coal royalties expense. Mining activity on our subleased property fluctuates between periods due to the proximity of our property boundaries and other mineral owners.

DD&A expenses increased for the comparative periods due to the increase in coal production and related depletion expense.

The following table sets forth a summary of certain financial and other data for our coal and natural resource management
segment and the percentage change for the periods presented:

Nine Months Ended September 30,

Favorable(Unfavorable)

%
ChangeFavorable(Unfavorable)

2011

2010

Financial Highlights

Revenues

Coal royalties

$

124,546

$

98,088

$

26,458

27

%

Coal services

6,739

5,976

763

13

%

Timber

3,834

4,488

(654

)

(15

%)

Oil and gas royalty

3,016

2,000

1,016

51

%

Other

6,294

3,998

2,296

57

%

Total revenues

144,429

114,550

29,879

26

%

Expenses

Operating

11,815

7,670

(4,145

)

(54

%)

General and administrative

14,151

13,219

(932

)

(7

%)

Depreciation, depletion and amortization

27,978

22,145

(5,833

)

(26

%)

Total expenses

53,944

43,034

(10,910

)

(25

%)

Operating income

$

90,485

$

71,516

18,969

27

%

Other data

Coal royalty tons by region

Central Appalachia

15,163

13,746

1,417

10

%

Northern Appalachia

2,840

2,935

(95

)

(3

%)

Illinois Basin

3,580

3,176

404

13

%

San Juan Basin

7,918

5,788

2,130

37

%

Total tons

29,501

25,645

3,856

15

%

Coal royalties revenues by region

Central Appalachia

$

91,069

$

70,592

$

20,477

29

%

Northern Appalachia

6,306

6,137

169

3

%

Illinois Basin

9,302

8,685

617

7

%

San Juan Basin

17,869

12,674

5,195

41

%

Total royalties

$

124,546

$

98,088

$

26,458

27

%

Coal royalties per ton by region ($/ton)

Central Appalachia

$

6.01

$

5.14

$

0.87

17

%

Northern Appalachia

2.22

2.09

0.13

6

%

Illinois Basin

2.60

2.73

(0.13

)

(5

%)

San Juan Basin

2.26

2.19

0.07

3

%

Average royalties per ton

$

4.22

$

3.82

$

0.40

10

%

Revenues

Coal royalties revenues increased due to higher production and realized coal royalties per ton. The Middle Fork acquisition on January 25, 2011 contributed $8.2 million to Central Appalachia coal
royalties and 1.3 million tons of coal production. Improved mining conditions, new mines starting up and the metallurgical coal market accounted for the remainder of the tonnage increase in Central Appalachia. Equipment added during 2010 to the
mines in the San Juan Basin continues to increase production and related coal royalties compared to the prior year.

Coal
royalties per ton increased in all regions in 2011 compared to last year, except for the Illinois Basin. In Central Appalachia, average coal prices received by lessees have increased due to the strong market pricing for thermal and metallurgical
coal. The reduced realized royalty rate in the Illinois Basin is due to contractual changes in royalties we receive on some properties in this region.

Consistent with the increase in coal production, the coal services revenues have increased
in 2011.

Timber revenues have decreased due to a decrease in timber harvested and average price received per board foot this
year. These decreases are associated with the depressed construction and furniture making industries.

Oil and gas royalty
income has increased in 2011 due to a settlement against a producer for deductions made on past royalties. The Middle Fork acquisition and the $0.4 million royalties earned from these properties have also contributed to the increase.

Other revenues in 2011 have increased due to minimum royalty forfeitures. Based upon lease contracts, which vary by lessee, lessees
paying minimum royalties have an established time to recoup minimum royalties paid. If the stated levels of production have not occurred after the exhaustion of that time period, the minimum payments are recognized into earnings. Additionally, a
gain on sale of property to a local oil and gas company related to their exploration activities was recognized in the second quarter of 2011 contributing to the increased other revenues for the year.

Expenses

Operating
expenses have increased primarily due to coal royalty costs and the recent Middle Fork acquisition. Increased mining activity by our lessees from subleased properties in the Central Appalachia region increased coal royalties expense. Mining activity
on our subleased property fluctuates between periods due to the proximity of our property boundaries and other mineral owners.

General and administrative expenses increased as a result of our change in management structure related to the Merger and some shared
costs (such as executive and legal costs) with our former parent, Penn Virginia Corporation, are no longer shared but are now direct costs of the Partnership. Also contributing to the increase were due diligence costs related to a recent
acquisition. Offsetting these increases are lower employee costs related to equity compensation. In the second quarter of last year, there was an acceleration of recognized equity compensation due to Penn Virginia Corporations divestiture of
its interest in PVG.

DD&A expenses increased for the comparative periods due to the increase in coal production and
related depletion expense.

Three Months Ended September 30, 2011 Compared with Three Months Ended September 30, 2010

The following table sets forth a summary of certain financial and other data for our natural gas midstream segment and the percentage change for the periods presented:

Three Months Ended September 30,

Favorable(Unfavorable)

%
ChangeFavorable(Unfavorable)

2011

2010

Financial Highlights

Revenues

Residue gas

$

120,240

$

98,534

$

21,706

22

%

Natural gas liquids

121,121

73,500

47,621

65

%

Condensate

8,268

4,814

3,454

72

%

Gathering, processing and transportation fees

10,081

3,359

6,722

200

%

Total natural gas midstream revenues

259,710

180,207

79,503

44

%

Equity earnings in equity investments

601

1,639

(1,038

)

(63

%)

Producer services and other

585

575

10

2

%

Total revenues

260,896

182,421

78,475

43

%

Expenses

Cost of gas purchased

223,762

151,657

(72,105

)

(48

%)

Operating

11,515

8,840

(2,675

)

(30

%)

General and administrative

4,984

4,706

(278

)

(6

%)

Depreciation and amortization

12,891

11,262

(1,629

)

(14

%)

Total operating expenses

253,152

176,465

(76,687

)

(43

%)

Operating income

$

7,744

$

5,956

$

1,788

30

%

Operating Statistics

Daily throughput volumes (MMcfd)

504

394

110

28

%

Gross margin

$

35,948

$

28,550

$

7,398

26

%

Cash impact of derivatives

(4,726

)

(584

)

(4,142

)

709

%

Gross margin, adjusted for impact of derivatives

$

31,222

$

27,966

$

3,256

12

%

Gross Margin

Gross margin is the difference between our natural gas midstream revenues and our cost of gas purchased. Natural gas midstream revenues included residue gas sold from processing plants after NGLs were
removed, NGLs sold after being removed from system throughput volumes received, condensate collected and sold and gathering and other fees primarily from natural gas volumes connected to our gas processing plants. Cost of gas purchased consisted of
amounts payable to third-party producers for natural gas purchased under percentage-of-proceeds and gas purchase/keep-whole contracts.

Overall, the gross margin increase was a result of higher system volumes, as well as higher NGL and higher fractionation, or frac, spreads. Frac spreads are the difference between the price of NGLs sold
and the cost of natural gas purchased on a per MMBtu basis. For the comparative quarters, natural gas prices were down. Offsetting the higher volumes and commodity prices was a change in contract mix. Given our completion of certain assets in the
Marcellus Shale, we gathered and transported an average of 63 MMcfd during the third quarter 2011 of fee-based volumes from these assets. This added to the mix a lower-risk, lower-margin element to our total gross margin. Gross margin from the
Marcellus System in the third quarter was $7.7 million. We process gas under three general types of contracts (gas purchase/keep whole contracts, percentage-of-proceeds contracts, and fee-based arrangements). These contracts are more fully described
in our Annual Report on Form 10-K for the year ended December 31, 2010. New gas volumes being added to our Panhandle system are primarily under fee-based processing percentage-of-proceeds contracts where we return the NGL revenue to the
producers. The result of this is a relative volumetric decrease in the higher commodity-risked, higher-margin gas purchase/keep whole contracts; however, the performance of these contracts does suffer during periods when we experience processing
capacity constraints.

Due to the increased well development activities in the Panhandle region of the Midstream
operations, our system volumes have increased significantly over past years volumes. The increase in the volumes we have under contract in the Granite Wash has outpaced the capacity of our processing plants in the Panhandle. Further,
third-party processing plants in the Panhandle region, that we have traditionally relied on to manage overruns in volumes, are fully utilized and unable to handle our excess volumes. Accordingly, we have had to forego processing a significant amount
of our volumes in the Panhandle which has adversely impacted our gross margins during the third quarter. Although we have recently been able to utilize some off system processing capacity, we expect these constraints to continue through the fourth
quarter and the beginning of the first quarter 2012. We have taken affirmative steps to alleviate this processing capacity constraint, including the acquisition of the Antelope Hills processing facility in June 2011, the previously announced Phase
One expansion of the Antelope Hills facility from 20 mmcf/day to 80 mmcf/day, and the most recently announced Phase Two expansion of that facility to bring the processing capacity to 140 mmcf/day. Phase One is scheduled to be in service in the first
quarter of 2012 and is expected to provide significant relief to our current processing capacity constraints. Phase Two is expected to be operational in the third quarter of 2012, and it will enable us to meet our expected future processing
requirements as volumes continue to grow. We are also improving the connectivity between our Antelope Hills, Beaver and Sweetwater plants to enable us to better utilize our Panhandle processing capabilities and better serve the growing needs of the
area producers, including those in the Granite Wash.

We generated a significant portion of our gross margin from contractual
arrangements under which the gross margin is exposed to increases and decreases in the price of natural gas and NGLs. As part of our risk management strategy, we use derivative financial instruments to hedge NGLs sold and natural gas purchased.
Midstream gross margin, including the cash impact of midstream derivatives, was $31.2 million compared to $28.0 million. This $3.2 million increase was primarily due to the increased system volumes, partially offset by a relative increase in
lower-risk, lower-margin, percentage of proceeds and fee-based contracts (as noted above), lower margins as a result of the capacity constraints, as well as increased derivative settlements given the higher commodity prices.

Expenses

Operating
expenses increased due to our expansion projects and acquisitions. The related costs of these growing or acquired facilities included increased costs of labor, chemicals, compressor rentals, and property tax.

Depreciation and amortization expenses increased primarily due to acquisitions and capital expansions in the Marcellus Shale and
Panhandle systems.

The following table sets forth a summary of certain financial and other data for our natural gas midstream segment and the
percentage change for the periods presented:

Nine Months EndedSeptember 30,

Favorable(Unfavorable)

%
ChangeFavorable(Unfavorable)

2011

2010

Financial Highlights

Revenues

Residue gas (1)

$

324,447

$

270,763

$

53,684

20

%

Natural gas liquids

345,247

199,320

145,927

73

%

Condensate

29,032

17,863

11,169

63

%

Gathering, processing and transportation fees

24,172

9,416

14,756

157

%

Total natural gas midstream revenues

722,898

497,362

225,536

45

%

Equity earnings in equity investments

2,569

4,919

(2,350

)

(48

%)

Producer services and other

2,305

1,908

397

21

%

Total revenues

727,772

504,189

223,583

44

%

Expenses

Cost of gas purchased (1)

613,295

415,111

(198,184

)

(48

%)

Operating

31,297

24,647

(6,650

)

(27

%)

General and administrative

17,549

18,357

808

4

%

Depreciation and amortization

37,379

32,638

(4,741

)

(15

%)

Total operating expenses

699,520

490,753

(208,767

)

(43

%)

Operating income

$

28,252

$

13,436

$

14,816

110

%

Operating Statistics

Daily throughput volumes (MMcfd)

462

341

121

35

%

Gross margin

$

109,603

$

82,251

$

27,352

33

%

Cash impact of derivatives

(13,628

)

(225

)

(13,403

)

(5957

%)

Gross margin, adjusted for impact of derivatives

$

95,975

$

82,026

$

13,949

17

%

(1)

For the period January 1 through June 7, 2010, we recorded $27.8 million of natural gas midstream revenues and $27.8 million for the cost of gas purchased
related to the purchase of natural gas from Penn Virginia Oil & Gas, L.P (a subsidiary of Penn Virginia Corporation and considered a related party up to June 7, 2010) and the subsequent sale of that gas to third parties. We took title
to the gas prior to transporting it to third parties. These transactions do not impact the gross margin.

Gross Margin

The gross margin increase was a result of higher system volumes, as well as higher NGL pricing and higher frac spreads. On
a year-to-date basis, natural gas prices were down for the comparative periods. Offsetting the higher volumes and frac spreads was a change in contract mix. Given our completion of certain assets in the Marcellus Shale, we gathered and transported
an average of 47 MMcfd during 2011 of fee-based volumes from these assets. This added to the mix a lower-risk, lower-margin element to our total gross margin. Gross margin from the Marcellus System in the nine months was $16.6 million. We process
gas under three general types of contracts (gas purchase/keep whole contracts, percentage-of-proceeds contracts, and fee-based arrangements). These contracts are more fully described in our Annual Report on Form 10-K for the year ended
December 31, 2010. New gas volumes being added to our Panhandle system are primarily under fee-based processing percentage-of-proceeds contracts where we return the NGL revenue to the producers. The result of this is a relative volumetric
decrease in the higher commodity-risked, higher-margin gas purchase/keep whole contracts; however, the performance of these contracts does suffer during periods when we experience processing capacity constraints.

Due to the increased well development activities in the Panhandle region of the Midstream operations, our system volumes have increased
significantly over past years volumes. The increase in the volumes we have under contract in the Granite Wash has outpaced the capacity of our processing plants in the Panhandle. Further, third-party processing plants in

the Panhandle region, that we have traditionally relied on to manage overruns in volumes, are fully utilized and unable to handle our excess volumes. Accordingly, we have had to forego processing
a significant amount of our volumes in the Panhandle which has adversely impacted our gross margins during the third quarter. Although we have recently been able to utilize some off system processing capacity, we expect these constraints to continue
through the fourth quarter and the beginning of the first quarter 2012. We have taken affirmative steps to alleviate this processing capacity constraint, including the acquisition of the Antelope Hills processing facility in June 2011, the
previously announced Phase One expansion of the Antelope Hills facility from 20 mmcf/day to 80 mmcf/day, and the most recently announced Phase Two expansion of that facility to bring the processing capacity to 140 mmcf/day. Phase One is scheduled to
be in service in the first quarter of 2012 and is expected to provide significant relief to our current processing capacity constraints. Phase Two is expected to be operational in the third quarter of 2012, and it will enable us to meet our expected
future processing requirements as volumes continue to grow. We are also improving the connectivity between our Antelope Hills, Beaver and Sweetwater plants to enable us to better utilize our Panhandle processing capabilities and better serve the
growing needs of the area producers, including those in the Granite Wash.

We generated a significant portion of our gross
margin from contractual arrangements under which the gross margin is exposed to increases and decreases in the price of natural gas and NGLs. As part of our risk management strategy, we use derivative financial instruments to hedge NGLs sold and
natural gas purchased. Midstream gross margin, including the cash impact of midstream derivatives, was $96.0 million compared to $82.0 million. This $14.0 million increase was primarily due to the increased system volumes, partially offset by a
relative increase in lower-risk, lower-margin, percentage of proceeds and fee-based contracts (as noted above), lower margins as a result of the capacity constraints, as well as increased derivative settlements given the higher commodity prices.

Expenses

Operating expenses increased due to our expansion projects and acquisitions. The related costs of these facilities included increased
costs of labor, chemicals, compressor rentals, and property tax.

General and administrative expenses decreased as a result of
the acceleration of recognized equity compensation in the second quarter of last year due to Penn Virginia Corporations divestiture of its interest in PVG. Offsetting this decrease are increased cost related to our change in management
structure due to the Merger and some shared costs (such as executive and legal costs) with our former parent, Penn Virginia Corporation, are no longer shared but are now direct costs of the Partnership. Also, we have incurred more due diligence
costs this year related to acquisitions.

Depreciation and amortization expenses increased primarily due to acquisitions and
capital expansions in the Marcellus Shale and Panhandle systems.

Our other results consist of interest expense and derivative gains and losses. The following table sets forth a summary of certain financial data for our other results for the periods presented:

Three Months Ended September 30,

Nine Months Ended September 30,

2011

2010

2011

2010

Operating income

$

37,575

$

31,693

$

118,737

$

82,161

Other income (expense)

Interest expense

(10,528

)

(10,639

)

(33,806

)

(25,368

)

Derivatives

8,690

(11,020

)

(6,289

)

(11,514

)

Other

120

111

384

654

Net income

$

35,857

$

10,145

$

79,026

$

45,933

Interest Expense. Our consolidated interest expense for the periods presented is comprised of the
following:

Three Months Ended September 30,

Nine Months Ended September 30,

Source

2011

2010

2011

2010

Interest on Revolver

$

(4,220

)

$

(2,889

)

$

(12,290

)

$

(9,518

)

Interest on Senior Notes

(6,188

)

(6,188

)

(18,563

)

(10,588

)

Debt issuance costs

(1,040

)

(1,633

)

(4,735

)

(4,243

)

Interest rate swaps







(1,090

)

Capitalized interest

920

71

1,782

71

Total interest expense

$

(10,528

)

$

(10,639

)

$

(33,806

)

$

(25,368

)

Interest expense, excluding capitalized interest, for the three and nine months ended September 30,
2011 has increased compared to the same periods in 2010. The increase is due to the issuance of the Senior Notes in April 2010 bearing an annual interest rate of 8.25%. The balance outstanding on the Revolver has increased given the acquisition and
internal growth initiatives. Additionally, in connection with the Revolver amendments, $1.6 million and $0.5 million of debt issuance costs were expensed in 2011 and 2010 related to banks that are no longer part of the bank group. The increase in
capitalized interest reflects the increase in internal growth projects and the related construction in progress for the Marcellus and Panhandle regions.

Derivatives. Our results of operations and operating cash flows were impacted by changes in market prices affecting fair values for NGL, crude oil and natural gas prices, as well as the Interest
Rate Swaps.

Commodity markets are volatile, and as a result, our hedging activity results can vary significantly. Our results
of operations are affected by the volatility of changes in fair value, which fluctuate with changes in NGL, crude oil and natural gas prices. We determine the fair values of our commodity derivative agreements based on discounted cash flows based on
quoted forward prices for the respective commodities. The discounted cash flows utilize discount rates adjusted for the credit risk of our counterparties for derivatives in an asset position and our own credit risk for derivatives in a liability
position.

Our derivative activity for the periods presented is summarized below:

Our operations and those of our coal lessees are subject to environmental laws and regulations adopted by various governmental authorities in the jurisdictions in which these operations are conducted. The
terms of our coal property leases impose liability on the relevant lessees for all environmental and reclamation liabilities arising under those laws and regulations. The lessees are bonded and have indemnified us against any and all future
environmental liabilities. We regularly visit our coal properties to monitor lessee compliance with environmental laws and regulations and to review mining activities. Our management believes that our operations and those of our lessees comply with
existing laws and regulations and does not expect any environment-related material adverse impact on our financial condition or results of operations.

As of September 30, 2011 and December 31, 2010, our environmental liabilities were $0.8 million and $0.9 million, which represents our best estimate of the liabilities as of those dates related
to our coal and natural resource management and natural gas midstream businesses. We have reclamation bonding requirements with respect to certain unleased and inactive properties. Given the uncertainty of when a reclamation area will meet
regulatory standards, a change in this estimate could occur in the future.

Critical Accounting Estimates

The process of preparing financial statements in accordance with accounting principles generally accepted in the United States of America
requires our management to make estimates and judgments regarding certain items and transactions. It is possible that materially different amounts could be recorded if these estimates and judgments change or if the actual results differ from these
estimates and judgments. Our most critical accounting estimates which involve the judgment of our management were fully disclosed in PVRs and PVGs Annual Reports on Form 10-K for the year ended December 31, 2010 and remained
unchanged as of September 30, 2011.

Item 3

Quantitative and Qualitative Disclosures About Market Risk

Market risk is the risk of loss arising from adverse changes in market rates and prices. The principal market risks to which we are
exposed are as follows:



Price Risk



Interest Rate Risk



Customer Credit Risk

As a result of our risk management activities as discussed below, we are also exposed to counterparty risk with financial institutions with whom we enter into these risk management positions.

We have completed a number of acquisitions in recent years. In conjunction with our accounting for these acquisitions, it was necessary
for us to estimate the values of the assets acquired and liabilities assumed, which involved the use of various assumptions. The most significant assumptions, and the ones requiring the most judgment, involve the estimated fair values of property,
plant and equipment, and the resulting amount of goodwill, if any. Changes in operations, decreases in commodity prices, changes in the business environment or deterioration of market conditions could substantially alter managements
assumptions and could result in lower estimates of values of acquired assets or of future cash flows. If these events occur, it is reasonably possible that we could record a significant impairment loss on our Consolidated Statements of Income.

Price Risk

Our price risk management program permits the utilization of derivative financial instruments (such as futures, forwards, option contracts
and swaps) to seek to mitigate the price risks associated with fluctuations in natural gas, NGL and crude oil prices as they relate to our natural gas midstream segment. The derivative financial instruments are placed with major financial
institutions that we believe are of acceptable credit risk. The fair values of our derivative financial instruments are significantly affected by fluctuations in the prices of natural gas, NGLs and crude oil.

At September 30, 2011, we reported a net commodity derivative liability related to our natural gas midstream segment of $7.6 million
that is with four counterparties and is substantially concentrated with two of those counterparties. This concentration may impact our overall credit risk, either positively or negatively, in that these counterparties may be similarly affected by
changes in economic or other conditions. We neither paid nor received collateral with respect to our derivative positions. No significant uncertainties related to the payment of amounts to or collectability of amounts owed to us exists with regard
to these counterparties.

For the three and nine months ended September 30, 2011, we reported a net derivative
gain of $8.7 million and a net derivative loss of $5.3 million for commodity derivatives. Because we do not use hedge accounting for our commodity derivatives, we recognize changes in fair value in earnings currently in the derivatives caption on
our Consolidated Statements of Income. We have experienced and could continue to experience significant changes in the estimate of derivative gains or losses recognized due to fluctuations in the value of our commodity derivative contracts. Our
results of operations are affected by the volatility of unrealized gains and losses and changes in fair value, which fluctuate with changes in natural gas, crude oil and NGL prices. These fluctuations could be significant in a volatile pricing
environment.

The following table lists our commodity derivative agreements for the period presented:

AverageVolumePer
Day

Swap Price

Weighted Average Price

Fair Value atSeptember 30, 2011

Put

Call

NGL  natural gasoline collar

(gallons

)

(per gallon)

Fourth quarter 2011

95,000

$

1.57

$

1.94

$

(2,492

)

NGL  natural gasoline collar

(gallons

)

(per gallon)

First quarter 2012 through fourth quarter 2012

54,000

$

1.75

$

2.02

(3,138

)

Crude oil collar

(barrels

)

(per barrel)

Fourth quarter 2011

400

$

75.00

$

98.50

109

Crude oil swap

(barrels

)

(per barrel

)

First quarter 2012 through fourth quarter 2012

600

$

88.62

1,604

Natural gas purchase swap

(MMBtu

)

(MMBtu

)

Fourth quarter 2011

6,500

$

5.80

(1,193

)

Natural gas purchase swap

(MMBtu

)

(MMBtu

)

First quarter 2012 through fourth quarter 2012

4,000

$

5.195

(1,370

)

Settlements to be paid in subsequent period

(1,165

)

$

(7,645

)

We estimate that a $5.00 per barrel increase in the crude oil price would decrease the fair value of our
crude oil collars by $1.2 million. We estimate that a $5.00 per barrel decrease in the crude oil price would increase the fair value of our crude oil collars by $1.2 million. We estimate that a $1.00 per MMBtu increase in the natural gas price would
increase the fair value of our natural gas purchase swaps by $1.9 million. We estimate that a $1.00 per MMBtu decrease in the natural gas price would decrease the fair value of our natural gas purchase swaps by $1.9 million. We estimate that a $0.10
per gallon increase in the natural gasoline (an NGL) price would decrease the fair value of our natural gasoline collar by $2.5 million. We estimate that a $0.10 per gallon decrease in the natural gasoline price would increase the fair value of our
natural gasoline collar by $2.5 million.

We estimate that, excluding the effects of derivative positions described above, for
every $1.00 per MMBtu increase or decrease in the natural gas price, our natural gas midstream gross margin and operating income for the remainder of 2011 would increase or decrease by $3.4 million. In addition, we estimate that for every $5.00 per
barrel increase or decrease in the crude oil price, our natural gas midstream gross margin and operating income for the remainder of 2011 would increase or decrease by $0.1 million. This assumes that natural gas prices, crude oil prices and inlet
volumes remain constant at anticipated levels. These estimated changes in our gross margin and operating income exclude potential cash receipts or payments in settling these derivative positions.

Interest Rate Risk

As
of September 30, 2011, we had $635.0 million of outstanding indebtedness under the Revolver, which carries a variable interest rate throughout its term. We entered into the Interest Rate Swaps to establish fixed interest rates on a portion of
the outstanding borrowings under the Revolver. From September 2011 to December 2011, the notional amounts of the Interest Rate Swaps total $250.0 million, or 39% of our outstanding indebtedness under the Revolver as of September 30, 2011, with
us paying a weighted average fixed rate of 3.37% on the notional amount, and the counterparties paying a variable

rate equal to the three-month LIBOR. From December 2011 to December 2012, the notional amounts of the Interest Rate Swaps total $100.0 million, or 16% of our outstanding indebtedness under the
Revolver as of September 30, 2011, with us paying a weighted average fixed rate of 2.09% on the notional amount, and the counterparties paying a variable rate equal to the three-month LIBOR. A 1% increase in short-term interest rates on the
floating rate debt outstanding under the Revolver (net of amounts fixed through the Interest Rate Swaps) as of September 30, 2011 would cost us approximately $3.9 million in additional interest expense per year.

Customer Credit Risk

We
are exposed to the credit risk of our customers and lessees. Approximately 84%, or $98.4 million, of our consolidated accounts receivable at September 30, 2011 resulted from our natural gas midstream segment and approximately 16%, or $18.2
million, resulted from our coal and natural resource management segment. Approximately $40.5 million of the natural gas midstream segments receivables at September 30, 2011 related to four customers, Conoco Phillips Company, Tenaska
Marketing Ventures, Targa Liquids Marketing and Trade and Williams NGL Marketing, LLC. At September 30, 2011, 41% of our natural gas midstream segment accounts receivable and 35% of our consolidated accounts receivable related to these natural
gas midstream customers. No significant uncertainties related to the collectability of amounts owed to us exist in regard to these natural gas midstream customers.

This customer concentration increases our exposure to credit risk on our accounts receivables, because the financial insolvency of any of these customers could have a significant impact on our results of
operations. If our natural gas midstream customers or coal lessees become financially insolvent, they may not be able to continue to operate or meet their payment obligations to us. Any material losses as a result of customer or lessee defaults
could harm and have an adverse effect on our business, financial condition or results of operations. Substantially all of our trade accounts receivable are unsecured.

To mitigate the risks of nonperformance by our natural gas midstream customers, we perform ongoing credit evaluations of our existing customers. We monitor individual customer payment capability in
granting credit arrangements to new customers by performing credit evaluations, seek to limit credit to amounts we believe the customers can pay and maintain reserves we believe are adequate to cover exposure for uncollectible accounts. As of
September 30, 2011, no receivables were collateralized, and we had a $0.3 million allowance for doubtful accounts, of which the majority related to our natural gas midstream segment.

Item 4

Controls and Procedures

(a) Disclosure Controls and Procedures

Under the supervision and with the
participation of our management, including our Chief Executive Officer and our Chief Financial Officer, we performed an evaluation of the design and operation of our disclosure controls and procedures (as defined in Rule 13a-15(e) of the Exchange
Act) as of September 30, 2011. Our disclosure controls and procedures are designed to ensure that information required to be disclosed by us in the reports we file or submit under the Exchange Act is recorded, processed, summarized and reported
accurately and on a timely basis. Based on that evaluation, our Chief Executive Officer and our Chief Financial Officer concluded that, as of September 30, 2011, such disclosure controls and procedures were effective.

(b) Changes in Internal Control Over Financial Reporting

No changes were made in our internal control over financial reporting during our last fiscal quarter that have materially affected, or are reasonably likely to materially affect, our internal control over
financial reporting.

For information on legal proceedings, see Part I, Item I, Financial Statements, Note 11, Commitments and Contingencies in the Notes to Unaudited Consolidated Financial Statements included in
this quarterly report, which is incorporated into this item by reference.

Item IA.

Risk Factors.

Part I, Item 1A, of the Partnerships Annual Report on Form 10-K for the year ended December 31, 2010, filed on February 24, 2011, includes a detailed discussion of the
Partnerships risk factors. The information below provides updates to the previously disclosed risk factors and when read in conjunction with the risk factors and information disclosed in the Partnerships 2010 Annual Report on Form 10-K
represent our currently known material risks.

Delays in obtaining, inability to obtain, or revocation of our lessees mining
permits and approvals could have an adverse effect on our coal royalties revenues.

Mine operators, including our
lessees, must obtain numerous permits and approvals that impose strict conditions and obligations relating to various environmental and safety matters in connection with coal mining. The permitting rules, and the interpretations of these rules are
complex, change frequently, and are often subject to discretionary interpretations by regulators, all of which may make compliance more difficult, and may possibly preclude the continuance of ongoing mining operations or the development of future
mining operations.

To dispose of mining overburden generated from surface mining activities, our lessees often need to obtain
government approvals, including CWA Section 404 permits to construct valley fills, stream impoundments, and sediment control ponds. Recently, these Section 404 permits and the Section 404 permitting standard have been the target of
increased scrutiny by environmental groups, legislators, the White House, and the EPA which has made it more difficult for miners to obtain, and in some cases maintain, Section 404 permits. In some cases, the EPA is retroactively rescinding
permits that have been issued. The U.S. Office of Surface Mining and Reclamation is in the process of rewriting the stream buffer zone rule which currently requires surface mining operators to minimize soil disturbances and dispose of
excess mining spoil away from water sources. If the EPA promulgates a more restrictive stream buffer zone rule, any such additional requirements could impact coal mining operations, particularly in Appalachia, including, for example, by reducing
locations where coal mining operations can be conducted or by further restricting common spoil disposal practices. Regulations which dramatically increase the costs of compliance or prohibit our lessees from obtaining new permits could reduce coal
production and cash flows, and could ultimately have an adverse effect on our royalty revenues.

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